Method to extract bitumen from oil sands

ABSTRACT

The present invention relates to an improved bitumen recovery process from oil sands. The oil sands may be surface mined and transported to a treatment area or may be treated directly by means of an in situ process of oil sand deposits that are located too deep for strip mining. Specifically, the present invention involves the step of treating oil sands with a propylene oxide capped glycol ether described by the structure: RO—(C 2 H 4 O) n —CH 2 CH(CH 3 )OH wherein R is a linear, branched, or cyclic alkyl, phenyl, alkyl phenyl group and n is 1 to 10.

FIELD OF THE INVENTION

The present invention relates to the recovery of bitumen from oil sands.More particularly, the present invention is an improved method forbitumen recovery from oil sands through either surface mining or in siturecovery. The improvement is the use of a propylene oxide capped glycolether as an extraction aid in the water and/or steam used in the bitumenrecovery process.

BACKGROUND OF THE INVENTION

Deposits of oil sands are found around the world, but most prominentlyin Canada, Venezuela, and the United States. These oil sands containsignificant deposits of heavy oil, typically referred to as bitumen. Thebitumen from these oil sands may be extracted and refined into syntheticoil or directly into petroleum products. The difficulty with bitumenlies in that it typically is very viscous, sometimes to the point ofbeing more solid than liquid. Thus, bitumen typically does not flow asless viscous, or lighter, crude oils do.

Because of the viscous nature of bitumen, it cannot be produced from awell drilled into the oil sands as is the case with lighter crude oil.This is so because the bitumen simply does not flow without being firstheated, diluted, and/or upgraded. Since normal oil drilling practicesare inadequate to produce bitumen, several methods have been developedover several decades to extract and process oil sands to remove thebitumen. For shallow deposits of oil sands, a typical method includessurface extraction, or mining, followed by subsequent treatment of theoil sands to remove the bitumen.

The development of surface extraction processes has occurred mostextensively in the Athabasca field of Canada. In these processes, theoil sands are mined, typically through strip or open pit mining withdraglines, bucket-wheel excavators, and, more recently, shovel and truckoperations. The oil sands are then transported to a facility to processand remove the bitumen from the sands. These processes typically involvea solvent of some type, most often water or steam, although othersolvents, such as hydrocarbon solvents, have been used.

After excavation, a hot water extraction process is typically used inthe Athabasca field in which the oil sands are mixed with water attemperatures ranging from approximately 35° C. to 75° C., with recentimprovements lowering the temperature necessary to the lower portion ofthe range. An extraction agent, such as sodium hydroxide (NaOH),surfactants, and/or air may be mixed with the oil sands.

Water is added to the oil sands to create an oil sands slurry, to whichadditives such as NaOH may be added, which is then transported to anextraction plant, typically via a pipeline. Inside a separation vessel,the slurry is agitated and the water and NaOH releases the bitumen fromthe oil sands. Air entrained with the water and NaOH attaches to thebitumen, allowing it to float to the top of the slurry mixture andcreate a froth. The bitumen froth is further treated to remove residualwater and fines, which are typically small sand and clay particles. Thebitumen is then either stored for further treatment or immediatelytreated, either chemically or mixed with lighter petroleum products, andtransported by pipeline for upgrading into synthetic crude oil.Unfortunately, this method cannot be used for deeper tar sand layers. Insitu techniques are necessary to recover deeper oil in well production.It is estimated that around 80 percent of the Alberta tar sands andalmost all of the Venezuelan tar sands are too far below the surface touse open pit mining.

In well production, referred to as in situ recovery, Cyclic SteamStimulation (CSS) is the conventional “huff and puff” in situ methodwhereby steam is injected into the well at a temperature of 250° C. to400° C. The steam rises and heats the bitumen, decreasing its viscosity.The well is allowed to sit for days or weeks, and then hot oil mixedwith condensed steam is pumped out for a period of weeks or months. Theprocess is then repeated. Unfortunately, the “huff and puff” methodrequires the site to be shut down for weeks to allow pumpable oil toaccumulate. In addition to the high cost to inject steam, the CSS methodtypically results in 20 to 25 percent recovery of the available oil.

Steam Assisted Gravity Drainage (SAGD) is another in situ method wheretwo horizontal wells are drilled in the tar sands, one at the bottom ofthe formation and another five meters above it. The wells are drilled ingroups off of central pads. These wells may extend for miles in alldirections. Steam is injected into the upper well, thereby melting thebitumen which then flows into the lower well. The resulting liquid oilmixed with condensed steam is subsequently pumped to the surface.Typical recovery of the available oil is 40 to 60 percent.

The above methods have many costs, environmental and safety problemsassociated with them. For example, the use of large amounts of steam isenergy intensive and requires the processing and disposal of largeamounts of water. Currently, tar sands extraction and processingrequires several barrels of water for each barrel of oil produced. Stripmining and further treatment results in incompletely cleaned sand, whichrequires further processing, before it can be returned to theenvironment. Further, the use of a large quantity of caustic in surfacemining not only presents process safety hazards but also contributesformation of fine clay particles in tailings, the disposal of which is amajor environmental problem.

Thus, there remains a need for efficient, safe and cost-effectivemethods to improve the recovery of bitumen from oil sands.

SUMMARY OF THE INVENTION

The present invention is an improved bitumen recovery process comprisingthe step of treating oil sands with a propylene oxide capped glycolether wherein the treatment is to oil sands recovered by surface miningor in situ production to oil sands in a subterranean reservoir.

In one embodiment of the bitumen recovery process described hereinabove, the propylene oxide capped glycol ether is described by thestructure:

RO—(C₂H₄O)_(n)—CH₂CH(CH₃)OH

wherein R is a linear, branched, cyclic alkyl, phenyl, or alkyl phenylgroup and n is 1 to 10, preferably 1 to 3, preferably the propyleneoxide capped glycol ether is one of, or a combination thereof, thepropylene oxide capped n-butyl ether of ethylene glycol, n-butyl etherof diethylene glycol, n-pentyl ether of ethylene glycol, n-pentyl etherof diethylene glycol, 2-methyl-1-pentyl ether of ethylene glycol,2-methyl-1-pentyl ether of diethylene glycol, n-hexyl ether of ethyleneglycol, n-hexyl ether of diethylene glycol, n-heptyl ether of ethyleneglycol, n-heptyl ether of diethylene glycol, n-octyl ether of ethyleneglycol, n-octyl ether of diethylene glycol, 2-ethylhexyl ether ofethylene glycol, 2-ethylhexyl ether of diethylene glycol, 2-propylheptylether of ethylene glycol, 2-propylheptyl ether of diethylene glycol,phenyl ether of ethylene glycol, phenyl ether of diethylene glycol,cyclohexyl ether of ethylene glycol, or cyclohexyl ether of diethyleneglycol.

In another embodiment of the present invention, the bitumen recoveryprocess by surface mining described herein above comprises the steps of:i) surface mining oil sands, ii) preparing an aqueous slurry of the oilsands, iii) treating the aqueous slurry with the propylene oxide cappedglycol ether, iv) agitating the treated aqueous slurry, v) transferringthe agitated treated aqueous slurry to a separation tank, and vi)separating the bitumen from the aqueous portion, preferably thepropylene oxide capped glycol ether is present in the aqueous slurry inan amount of from 0.01 to 10 weight percent based on the weight of theoil sands.

In another embodiment of the present invention, the bitumen recoveryprocess by in situ production described herein above comprises the stepsof: i) treating a subterranean reservoir of oil sands by injecting steamcontaining the propylene oxide capped glycol ether into a well, and ii)recovering the bitumen from the well, preferably the concentration ofthe propylene oxide capped glycol ether in the steam is in an amount offrom 100 ppm to 10 weight percent.

DETAILED DESCRIPTION OF THE EMBODIMENTS

The separation of bitumen and/or heavy oil from oil sands isaccomplished by, but not limited to, two methods, surface mining or insitu recovery sometimes referred to as well production. The oil sandsmay be recovered by surface or strip mining and transported to atreatment area. A good summary can be found in the article“Understanding Water-Based Bitumen Extraction from Athabasca Oil Sands”,J. Masliyah, et al., Canadian Journal of Chemical Engineering, Volume82, August 2004. The basic steps in bitumen recovery via surface mininginclude: extraction, froth treatment, tailings treatment, and upgrading.The steps are interrelated; the mining operation affects the extractionand in turn the extraction affects the upgrading operation.

Typically, in commercial bitumen recovery operations, the oil sand ismined in an open-pit mine using trucks and shovels. The mined oil sandsare transported to a treatment area. The extraction step includescrushing the oil sand lumps and mixing them with (recycle process) waterin mixing boxes, stirred tanks, cyclo-feeders or rotary breakers to forma conditioned oil sands slurry. The conditioned oil sands slurry isintroduced to hydrotransport pipelines or to tumblers, where the oilsand lumps are sheared and size reduction takes place. Within thetumblers and/or the hydrotransport pipelines, bitumen is recovered or“released”, or “liberated”, from the sand grains. Chemical additives canbe added during the slurry preparation stage; for examples of chemicalsknown in the art see US2008/0139418, incorporated by reference herein inits entirety. In typical operations, the operating slurry temperatureranges from 35° C. to 75° C., preferably 40° C. to 55° C.

Entrained or introduced air attaches to bitumen in the tumblers andhydrotransport pipelines creating froth. In the froth treatment step,the aerated bitumen floats and is subsequently skimmed off from theslurry. This is accomplished in large gravity separation vessels,normally referred to as primary separation vessels (PSV), separationcells (Sep Cell) or primary separation cells (PSC). Small amounts ofbitumen droplets (usually un-aerated bitumen) remaining in the slurryare further recovered using either induced air flotation in mechanicalflotation cells and tailings oil recovery vessels, or cyclo-separatorsand hydrocyclones. Generally, overall bitumen recovery in commercialoperations is about 88 to 95 percent of the original oil in place. Therecovered bitumen in the form of froth normally contains 60 percentbitumen, 30 percent water and 10 percent solids.

The bitumen froth recovered as such is then de-aerated, and diluted(mixed) with solvents to provide sufficient density difference betweenwater and bitumen and to reduce the bitumen viscosity. The dilution by asolvent (e.g., naphtha or hexane) facilitates the removal of the solidsand water from the bitumen froth using inclined plate settlers, cyclonesand/or centrifuges. When a paraffinic diluent (solvent) is used at asufficiently high diluent to bitumen ratio, partial precipitation ofasphaltenes occurs. This leads to the formation of composite aggregatesthat trap the water and solids in the diluted bitumen froth. In this waygravity separation is greatly enhanced, potentially eliminating the needfor cyclones or centrifuges.

In the tailings treatment step, the tailings stream from the extractionplant goes to the tailings pond for solid-liquid separation. Theclarified water is recycled from the pond back to the extraction plant.To accelerate tailings handling, gypsum may be added to mature finetailings to consolidate the fines together with the coarse sand into anon-segregating mixture. This method is referred to as the consolidated(composite) tailing (CT) process. CT is disposed of in a geotechnicalmanner that enhances its further dewatering and eventual reclamation.Optionally, tailings from the extraction plant are cycloned, with theoverflow (fine tailings) being pumped to thickeners and the cycloneunderflow (coarse tailings) to the tailings pond. Fine tailings aretreated with flocculants, then thickened and pumped to a tailings pond.Further, the use of paste technology (addition offlocculants/polyelectrolytes) or a combination of CT and pastetechnology may be used for fast water release and recycle of the waterin CT to the extraction plant for bitumen recovery from oil sands.

In the final step, the recovered bitumen is upgraded. Upgrading eitheradds hydrogen or removes carbon in order to achieve a balanced, lighterhydrocarbon that is more valuable and easier to refine. The upgradingprocess also removes contaminants such as heavy metals, salts, oxygen,nitrogen and sulfur. The upgrading process includes one or more stepssuch as: distillation wherein various compounds are separated byphysical properties, coking, hydro-conversion, solvent deasphalting toimprove the hydrogen to carbon ratio, and hydrotreating which removescontaminants such as sulfur.

In one embodiment of the present invention, the improvement to theprocess of recovering bitumen from oil sands is the addition of apropylene oxide capped glycol ether during the slurry preparation stage.The sized material is added to a slurry tank with agitation and combinedwith a propylene oxide capped glycol ether. The propylene oxide cappedglycol ether may be added to the oil sands slurry neat or as an aqueoussolution having a concentration of from 100 ppm to 10 weight percentpropylene oxide capped glycol ether based on the total weight of thepropylene oxide capped glycol ether solution. Preferably, the propyleneoxide capped glycol ether is present in the aqueous oil sands slurry inan amount of from 0.01 to 10 weight percent based on the weight of theoil sands.

Preferred propylene oxide capped glycol ethers of the present inventionare represented by the following formula:

RO—(C₂H₄O)_(n)—CH₂CH(CH₃)OH

-   -   wherein R is a linear, branched, or cyclic alkyl, phenyl, alkyl        phenyl group and    -   n is 1 to 10, preferably 1 to 3.        Preferred propylene oxide capped propylene oxide capped glycol        ethers of the present invention are the propylene oxide capped        n-butyl ether of ethylene glycol, n-butyl ether of diethylene        glycol, n-pentyl ether of ethylene glycol, n-pentyl ether of        diethylene glycol, 2-methyl-1-pentyl ether of ethylene glycol,        2-methyl-1-pentyl ether of diethylene glycol, n-hexyl ether of        ethylene glycol, n-hexyl ether of diethylene glycol, n-heptyl        ether of ethylene glycol, n-heptyl ether of diethylene glycol,        n-octyl ether of ethylene glycol, n-octyl ether of diethylene        glycol, 2-ethylhexyl ether of ethylene glycol, 2-ethylhexyl        ether of diethylene glycol, 2-propylheptyl ether of ethylene        glycol, 2-propylheptyl ether of diethylene glycol, phenyl ether        of ethylene glycol, phenyl ether of diethylene glycol,        cyclohexyl ether of ethylene glycol, cyclohexyl ether of        diethylene glycol, or mixtures thereof.

The propylene oxide capped glycol ether solution/oil sand slurry istypically agitated from 5 minutes to 4 hours, preferably for an hour orless. Preferably, the propylene oxide capped glycol ether solution oilsands slurry is heated to equal to or greater than 35° C., morepreferably equal to or greater than 40° C., more preferably equal to orgreater than 55° C., more preferably equal to or greater than 60° C.Preferably, the propylene oxide capped glycol ether solution oil sandsslurry is heated to equal to or less than 100° C., more preferably equalto or less than 80° C., and more preferably equal to or less than 75° C.

As outlined herein above, the propylene oxide capped glycol ethertreated slurry may be transferred to a separation tank, typicallycomprising a diluted detergent solution, wherein the bitumen and heavyoils are separated from the aqueous portion. The solids and the aqueousportion may be further treated to remove any additional free organicmatter.

In another embodiment of the present invention, bitumen is recoveredfrom oil sands through well production wherein the propylene oxidecapped glycol ether as described herein above can be added to oil sandsby means of in situ treatment of the oil sand deposits that are locatedtoo deep for strip mining. The two most common methods of in situproduction recovery are cyclic steam stimulation (CSS) andsteam-assisted gravity drainage (SAGD). CSS can utilize both verticaland horizontal wells that alternately inject steam and pump heatedbitumen to the surface, forming a cycle of injection, heating, flow andextraction. SAGD utilizes pairs of horizontal wells placed one over theother within the bitumen pay zone. The upper well is used to injectsteam, creating a permanent heated chamber within which the heatedbitumen flows by gravity to the lower well, which extracts the bitumen.However, new technologies, such as vapor recovery extraction (VAPEX) andcold heavy oil production with sand (CHOPS) are being developed.

The basic steps in the in situ treatment to recover bitumen from oilsands includes: steam injection into a well, recovery of bitumen fromthe well, and dilution of the recovered bitumen, for example withcondensate, for shipping by pipelines.

In accordance with this method, the propylene oxide capped glycol etheris used as a steam additive in a bitumen recovery process from asubterranean oil sand reservoir. The mode of steam injection may includeone or more of steam drive, steam soak, or cyclic steam injection in asingle or multi-well program. Water flooding may be used in addition toone or more of the steam injection methods listed herein above.

Typically, the steam is injected into an oil sands reservoir through aninjection well, and wherein formation fluids, comprising reservoir andinjection fluids, are produced either through an adjacent productionwell or by back flowing into the injection well.

In most oil sand reservoirs, a steam temperature of at least 180° C.,which corresponds to a pressure of 150 psi (1.0 MPa), or greater isneeded to mobilize the bitumen. Preferably, the propylene oxide cappedglycol ether-steam injection stream is introduced to the reservoir at atemperature in the range of from 150° C. to 300° C., preferably 180° C.to 260° C. The particular steam temperature and pressure used in theprocess of the present invention will depend on such specific reservoircharacteristics as depth, overburden pressure, pay zone thickness, andbitumen viscosity, and thus will be worked out for each reservoir.

It is preferable to inject the propylene oxide capped glycol ethersimultaneously with the steam in order to ensure or maximize the amountof propylene oxide capped glycol ether actually moving with the steam.In some instances, it may be desirable to precede or follow asteam-propylene oxide capped glycol ether injection stream with asteam-only injection stream. In this case, the steam temperature can beraised above 260° C. during the steam-only injection. The term “steam”used herein is meant to include superheated steam, saturated steam, andless than 100 percent quality steam.

For purposes of clarity, the term “less than 100 percent quality steam”refers to steam having a liquid water phase present. Steam quality isdefined as the weight percent of dry steam contained in a unit weight ofa steam-liquid mixture. “Saturated steam” is used synonymously with “100percent quality steam”. “Superheated steam” is steam which has beenheated above the vapor-liquid equilibrium point. If super heated steamis used, the steam is preferably super heated to between 5 to 50° C.above the vapor-liquid equilibrium temperature, prior to adding thepropylene oxide capped glycol ether.

The propylene oxide capped glycol ether may be added to the steam neator as a concentrate. If added as a concentrate, it may be added as a 1to 99 weight percent solution in water. Preferably, the propylene oxidecapped glycol ether is substantially volatilized and carried into thereservoir as an aerosol or mist. Here again, the rationale is tomaximize the amount of propylene oxide capped glycol ether travelingwith the steam into the reservoir.

The propylene oxide capped glycol ether is preferably injectedintermittently or continuously with the steam, so that thesteam-propylene oxide capped glycol ether injection stream reaches thedownhole formation through common tubing. The rate of propylene oxidecapped glycol ether addition is adjusted so as to maintain the preferredpropylene oxide capped glycol ether concentration of 100 ppm to 10weight percent in steam. The rate of steam injection for a typical oilsands reservoir might be on the order of enough steam to provide anadvance through the formation of from 1 to 3 feet/day.

Examples

Example 1 is 1-(2-butoxyethoxy) propan-2-ol, a propylene oxide cappedglycol ether of the present invention. It is prepared as follows: A 2 LParr reactor is charged with 898.3 g (7.602 mol) of ethylene glycolbutyl ether and 4.00 g of powdered potassium hydroxide (KOH). The systemis sealed and pressure checked with nitrogen, then heated to 120° C. Atotal of 221.9 g (3.821 mol) of propylene oxide is added at a rate of 1to 5 g/min over 50 minutes. The reactor pressure rises from 11 to 42 psiduring the addition, then is increased to 200 psi by blowing through theaddition cylinder with nitrogen. The reactor is held at 120° C. for anadditional 3.5 hours, then cooled and the reaction product unloaded toafford 1104.35 g of clear solution. Phosphoric acid (3.411 g of 85%) isadded dropwise to the product solution; after stirring for 5 minutes,the solution is titrated for residual base (0.0% KOH). The clearsolution (1081.5 g) is charged to a 2 L distillation flask for vacuumdistillation. Six fractions are collected and fractions 4, 5, and 6 arecombined to afford 334 g of 1-(2-butoxyethoxy)propan-2-ol (99.75 area %,by GC analysis).

Example 2 is 1-(2-hexoxyethoxy) propan-2-ol a propylene oxide cappedglycol ether of the present invention. It is prepared as follows: A 2 LParr reactor is charged with 1000.5 g (6.842 mol) of ethylene glycolhexyl ether and 4.2 g of powdered KOH. The system is sealed and pressurechecked with nitrogen, then heated to 120° C. A total of 256.8 g (4.421mol) of propylene oxide is added at a rate of 1 to 5 g/min over 56minutes. The reactor pressure rises from 16 to 55 psi during theaddition, then is increased to 200 psi by blowing through the additioncylinder with nitrogen. The reactor is held at 120° C. for an additional2 hours, then it is cooled and the reaction product unloaded. The clearsolution (1240 g) is combined with 471.3 g of a second reaction productfrom 408.7 g (2.795 mol) of ethylene glycol monohexyl ether, 1.224 g ofpowdered KOH, and 82.3 g (1.42 mol) of propylene oxide and mixed with4.058 g of 85% phosphoric acid; after stirring for 5 minutes, thesolution is titrated for residual base. The clear solution (1690.9 g) ischarged to a 3 L distillation flask for vacuum distillation. Sevenfractions are collected and fractions 6 and 7 are combined to afford607.4 g of propylene oxide capped ethylene glycol of hexyl ether (99.84area %, by GC analysis).

Comparative Example A is diethylene glycol of butyl ether available asButyl CARBITOL™ from The Dow Chemical Company.

Comparative Example B is diethylene glycol of hexyl ether available asHexyl CARBITOL from The Dow Chemical Company.

Oil/water interfacial tension (IFT) is measured using a pendant droptensiometer, with decane as the model oil. 2000 ppm solution of theglycol ether in water is prepared, and a decane drop is created with asyringe into that solution. All measurements are made under ambientconditions.

Steam flooding experiments are conducted as follows: steam is generatedby pumping 1 mL/min of water from a reservoir through a heat exchanger.When testing a glycol ether, the water is replaced with a 4000 ppmglycol ether solution in water. The produced steam or steam+glycol ethervapor mix is injected to the top of a stainless steel chamber containinga synthetic oil sand core, prepared by mechanically compressing a 100 gsample of mined oil sand. Steam injection is maintained forapproximately three hours, during which the produced bitumen andcondensate are collected from the bottom of the chamber through a valve,which remains open to the atmosphere. The bed temperature is around 100°C.

Steam soaking experiments are conducted as follows: A 500 mL Parrreactor is loaded with approximately 150 mL of water or 2.5 wt %additive/water mix. A synthetic oil sand core prepared by mechanicallycompressing 50 g of mined oil sand is placed in a mesh basket and hungfrom the lid of the Parr reactor such that the core is not touching theliquid phase at the bottom. The reactor is sealed and then heated to188° C. for 4 hours. After cooling the reactor overnight, the producedoil and the spent sand are analyzed to determine the oil recovery.

Table 1 summarizes the experimental results for Examples 1 and 2 andComparative Examples A and B. The experimental uncertainty of IFTmeasurement is less than 0.5 mN/m. The experimental uncertainty of steamflooding data is less than 1 wt %. The experimental uncertainty of steamsoaking data is less than 10 wt %.

TABLE 1 Decane/Water Oil Recovery from Oil Recovery from IFT (mN/m)Steam Flooding at Steam Soaking at at 2000 ppm 4000 ppm 2.5% Comparative32.7 18% 18% Example A Example 1 32.2 20% 33% Comparative 20.2 25% 45%Example B Example 2 21.6 27% 49%

Large scale 1D gravity drainage experiments are conducted as follows: Asynthetic bitumen-saturated core of 5 inch length is prepared and issuspended inside a core holder. The bitumen-saturated core is preparedin a mesh sleeve which allows steam to diffuse in the core and interact.This arrangement ensures that the released bitumen flow only under theaction of gravity and not due to any external pressure. To prolong theexisting of condensation of steam front inside the core, a cold fingeris used to maintain temperature gradient in the radial direction acrossthe core. Steam alone (e.g., without any glycol ether) is run as abaseline. Examples 1 and 2 are injected into the steam line directly ata rate which is to provide a final glycol ether concentration of 4000ppm. The chamber pressure is controlled by a back pressure regulator(BPR) attached at the bottom of the chamber. The pressure inside thechamber is increased in incremental steps of 20 psi and is continuedutilizing a standard operating procedure until a final pressure of 150psi is reached, where it is held constant. The drained bitumen and wateris collected as a function of time and is later quantified usingsolvent-extraction and gravity method to obtain recovery v/s time plot.Uncondensed vapors coming out of the chamber is arrested using a vaportrap. Drainage experiments are run for around 6 hours. The produced oiland the spent sand are analyzed to determine the oil recovery. Table 2shows the total oil recovered based on the amount of oil left in thespent sand at the end of the run.

TABLE 2 Oil Recovery Steam Only 30% Example 1, @ 4000 ppm 48% Example 2,@ 4000 ppm 41%

What is claimed is:
 1. A bitumen recovery process comprising the step oftreating oil sands with a propylene oxide capped glycol ether whereinthe treatment is to oil sands recovered by surface mining or in situproduction.
 2. The process of claim 1 wherein the propylene oxide cappedglycol ether is described by the following structure:RO—(C₂H₄O)_(n)—CH₂CH(CH₃)OH wherein R is a linear, branched, cyclicalkyl, phenyl, or alkyl phenyl group and n is 1 to
 10. 3. The bitumenrecovery process of claim 1 by surface mining comprising the steps of:i) surface mining oil sands, ii) preparing an aqueous slurry of the oilsands, iii) treating the aqueous slurry with the propylene oxide cappedglycol ether, iv) agitating the treated aqueous slurry, v) transferringthe agitated treated aqueous slurry to a separation tank, and vi)separating the bitumen from the aqueous portion.
 4. The bitumen recoveryprocess of claim 3 wherein the propylene oxide capped glycol ether ispresent in the aqueous slurry in an amount of from 0.01 to 10 weightpercent based on the weight of the oil sands.
 5. The bitumen recoveryprocess of claim 1 by in situ production comprising the steps of: i)treating a subterranean reservoir of oil sands by injecting steamcontaining the propylene oxide capped glycol ether into a well, and ii)recovering the bitumen from the well.
 6. The bitumen recovery process ofclaim 5 wherein the concentration of the propylene oxide capped glycolether in the steam is in an amount of from 100 ppm to 10 weight percent.7. The process of claim 1 wherein the propylene oxide capped glycolether is a propylene oxide capped n-butyl ether of ethylene glycol,n-butyl ether of diethylene glycol, n-pentyl ether of ethylene glycol,n-pentyl ether of diethylene glycol, 2-methyl-1-pentyl ether of ethyleneglycol, 2-methyl-1-pentyl ether of diethylene glycol, n-hexyl ether ofethylene glycol, n-hexyl ether of diethylene glycol, n-heptyl ether ofethylene glycol, n-heptyl ether of diethylene glycol, n-octyl ether ofethylene glycol, n-octyl ether of diethylene glycol, 2-ethylhexyl etherof ethylene glycol, 2-ethylhexyl ether of diethylene glycol,2-propylheptyl ether of ethylene glycol, 2-propylheptyl ether ofdiethylene glycol, phenyl ether of ethylene glycol, phenyl ether ofdiethylene glycol, cyclohexyl ether of ethylene glycol, cyclohexyl etherof diethylene glycol, or mixtures thereof.